In development of remote or marginal offshore oil and gas fields, subsea developments are often selected in order to reduce investments in production facilities. Although the hydrocarbons produced on site need processing, the number of subsea process units is preferably low and the units of reduced complexity for minimal maintenance and in order to avoid malfunctions. For further processing it is desirable to utilise process capacity within existing infrastructure either offshore or onshore, which may require transportation over long distances by pipelines.
The hydrocarbon well fluid will often contain both oil and gas which may be separated in a subsea separation unit and then either transported separately to the same processing unit or be transported to different processing units to utilize capacity of surrounding infrastructure. The produced hydrocarbon-containing fluid is warm when entering the wellhead, generally in the range of 60-130° C. and will in addition to hydrocarbons contain liquid water and water in the gas phase corresponding to the water vapour pressure at the current temperature and pressure. If the gas is transported untreated over long distances, it will cool, the water in gas phase will condense and below the hydrate formation temperature, hydrates will form. The hydrate formation temperature is in the range of 20-30° C. between 100-400 bara.
Hydrates are ice-like crystalline solids composed of water and gas, and hydrate depositions at the inside wall of gas and/or oil pipelines is a severe problem in today's oil and gas production infrastructure. When warm hydrocarbon fluid containing water flows through a pipeline with cold walls, hydrates will precipitate and adhere to the inner walls. This in turn will reduce the pipeline cross-sectional area, which without proper counter measures will lead to a loss of pressure and ultimately to a complete blockage of the pipeline or other process equipment. Transportation of gas over distance will therefore normally require hydrate control.
Existing technologies that deal with the problem of removing such deposits or avoiding them include:                Addition of inhibitors (thermodynamic or kinetic), which prevent hydrate deposition.        Electric heating and insulation keeping the pipeline warm (above the hydrate appearance temperature).        Mechanical scraping off the deposits from the inner pipe wall at regular intervals by pigging.        
To avoid formation of hydrate, a thermodynamic or kinetic hydrate inhibitor can be added, such as an alcohol (methanol or ethanol) or a glycol such as Monoethylene Glycol (MEG or 1,2-ethanediol), which is inexpensive and simple to inject. However, if the water content is high, proportional large amounts of inhibitor are needed which at the receiving end or on site will require a hydrate inhibitor regeneration process unit with sufficient capacity to recover and recycle the inhibitor. A recovery may be performed by a MEG regeneration unit, but will contribute to an increase in both costs and investments, especially if installed on site at subsea level.
Therefore, there is a need for removing both liquid water and water in the gas phase from a produced hydrocarbon-containing fluid, wherein the ratio of liquid and gas phase is dependent on the water vapour pressure at the prevailing temperature and pressure. The water removal in a hydrocarbon-containing gas, or the water dew-point depression, should be performed before the temperature of the fluid drops below the hydrate formation temperature and. In addition, reduced quantities of hydrate inhibitors compared to prior art should be used to avoid regeneration at subsea, i.e. before long transport by pipeline subsea in cold sea water, such as 5 km or more, for example 10, 20, 30, 50, 75 or 100 km or more.
Electric heating above the hydrate formation temperature is very expensive due to both high installation and operational costs. Accordingly, electric heating is not feasible for long-distance transport.
Another method to reduce or avoid the use of hydrate inhibitor is to insulate the pipeline and reduce the diameter to increase the flow rate and thereby reduce temperature loss and water accumulation. If the pipeline is not too long, such as in the order of 1-30 km, it will be possible to keep the temperature above the hydrate formation temperature, at which hydrates form. However, this reduces the operational window of the pipeline, and it will not have capacity for future higher gas rates and cannot be operated at low gas rates. Boosting might also be required, as the pipeline pressure drop will be important due to a small sized pipeline. In addition, hydrate formation will occur during production stops and shut downs as the hydrocarbons are cooled below the formation temperature.
Pigging is a complex and expensive operation. If no loop is available, a pig has to be inserted sub-sea using remote-operated vehicles. If more hydrates are deposited than the pig diameter is designed for, the pig might get stuck in the pipeline, resulting in costly operations and stop in production to remove the pig.
RU 2199375 concerns a method for absorption drying of hydrocarbon gas by using a primary separation step and a cooling step where the gas temperature and dew point of gas is controlled by addition of an absorbent before the cooler, and a second separation step where the absorbent is regenerated for further transport of the gas. The removal of bulk water in the first separation step reduces the load on the absorber, but with the use of an absorber at least one regeneration unit is necessary, which is undesirable in subsea installations.
U.S. Pat. No. 5,127,231 concerns the treatment of a gas from a production well by contacting the gas with a liquid phase, containing water and anti-hydrate additive, in a unit separating off a liquid phase and an additive charged gas which is transported over long distances, which may be several kilometers. An almost conventional drying process is described involving a contactor with absorbent (glycol). The gas is cooled during transport before entering a heat exchanger where condensate of water solvent and additive is separated from the gas in a settlement vessel. The liquid phase is recycled to the production site. Hence, anti-hydrate additive is added during the first separation and is present during the main transport before cooling, after which the additive is separated at the end reception terminal where the gas is treated.
The methods described above make use of recirculation of anti-hydrate additive introduced during the first separation step on the well stream. This introduction of additive necessitates an absorber unit for regeneration of the additive.
CA 2,040,833 concerns a method for preventing formation of hydrates in subsea piping by passing a well stream through a separator at controlled pressure, and boiling off light hydrocarbons form the liquid phase in such an extent that substantially no hydrates are formed. The formation may additionally be prevented by addition of glycol as hydrate inhibitor. The choking of the well stream to evaporate light components and water, results in a reduced pressure, which must be regained by a compressor. Depending on the gas/oil ratio (GOR) the amount of water and the composition of the stream resulting from the pressure reduction will vary and the application is therefore limited to fluids with a suitable phase diagram. In addition the entire well stream is cooled in this document, which requires a large capacity cooler.
An important object of the present invention is to reduce the number of process units at subsea and to minimize the amount of anti-hydrate additive is used, so that the gas phase from a production well that may be transported over large distances in cold water without causing hydrate formation, while requiring no or little additive regeneration when reaching a process unit.